CN111542679A - Method and system for monitoring and optimizing reservoir stimulation operations - Google Patents

Abstract

Methods and systems for monitoring and optimizing stimulation operations in a reservoir are provided. In particular, the methods and systems utilize downhole telemetry systems, such as networks of sensors and downhole wireless communication nodes, to monitor various stimulation operations.

Description

Method and system for monitoring and optimizing reservoir stimulation operations

Cross Reference to Related Applications

The present application claims benefit of U.S. provisional application serial No.62/611,655 entitled "Methods and Systems for monitoring and Optimizing Reservoir simulation Operations" filed on 29.12.2017, the entire disclosure of which is incorporated herein by reference.

Technical Field

The present disclosure relates to methods and systems for monitoring and optimizing reservoir stimulation operations. In particular, the present disclosure relates to methods and systems for monitoring and optimizing reservoir stimulation operations (such as acidizing operations and/or fracturing operations) using a downhole wireless network.

Background

The production capacity of a hydrocarbon-bearing subterranean formation (i.e., a hydrocarbon reservoir) may be related to a number of factors, including but not limited to the amount of hydrocarbons present in the formation; porosity and permeability of the formation; pressure within the formation; temperature within the formation; viscosity of hydrocarbons contained within the formation; a length of a wellbore exposed to a hydrocarbon containing formation; and the presence of water, gas, and/or other materials in the formation. Because of the wide variety of potential interactions between these various factors, the presence of hydrocarbons in subterranean formations by itself does not suggest that the hydrocarbons may be economically recovered. Accordingly, various techniques have been developed to stimulate a reservoir to increase the overall recovery of hydrocarbons from a subterranean formation and/or to facilitate the economic recovery of hydrocarbons from a low permeability reservoir.

For example, various chemical stimulation techniques have been developed, such as matrix acidizing techniques. In such techniques, a chemical substance, such as an acid, capable of dissolving the rock matrix is injected through the well. The chemical acts to remove certain rock material at the wellbore and clean up and enlarge formation pores in the near wellbore environment.

As another example, fracturing operations have been developed that include injecting a fracturing fluid into a formation at a high pressure and rate such that the rock matrix will "break apart" and form a fracture network. Various fracturing fluids may be used, such as shear thinning viscous fluids, non-newtonian gels or emulsions. Additionally, the fracturing fluid may be mixed with a proppant material (e.g., sand, ceramic beads, or other particulate material) to hold the fracture open after the hydraulic pressure is released.

It is desirable to be able to monitor the effectiveness of reservoir stimulation operations, such as fracturing operations and chemical stimulation operations. For example, it would be useful to have real-time information to assess the effectiveness of stimulation fluids when used. Such information may then be used to determine whether a different stimulation agent should be used, whether a stimulation fluid should be injected at a different pressure, and/or whether more or less stimulation fluid should be used. As another example, many stimulation operations are accomplished in a multi-stage operation, and may have two or more stages. Thus, it would be useful to have real-time downhole information during a stimulation operation to assess stimulation performance in one stage before proceeding to the next stage of the stimulation operation.

Thus, in reservoir stimulation operations, such as chemical stimulation operations and/or hydraulic fracturing operations, real-time information is needed to assess the performance of the stimulation operation. In addition, it is desirable to have real-time information at each stage of the stimulation operation to optimize and increase the efficiency of the stimulation operation.

Background references may include (i) U.S. patent No.5,924,499; 6,462,672, respectively; 6,899,178, respectively; 6,909,667, respectively; 6,912,177, respectively; 7,228,902, respectively; 7,249,636, respectively; 7,477,160, respectively; 8,115,651, respectively; 9,557,434, respectively; 9,631,485, respectively; 9,759,062, respectively; 9,816,373, respectively; 9,863,222, respectively; 9,879,525, respectively; 10,100,635, respectively; and 10,132,149; (ii) U.S. patent application publication No. 2008/0030365; 2015/0292319, respectively; 2015/0300159, respectively; 2015/0354351, respectively; 2016/0076363, respectively; 2016/0215612, respectively; 2018/005819, respectively; 2018/0058198, respectively; 2018/0058202, respectively; 2018/0058203, respectively; 2018/0058204, respectively; 2018/0058205, respectively; 2018/0058206, respectively; 2018/0058207, respectively; 2018/0058208, respectively; 2018/0058209, respectively; and 2018/0066510; and (iii) U.S. patent application Ser. No. 15/666334.

Drawings

FIG. 1 is a side cross-sectional view of an illustrative wellbore that has been completed as a cased hole completion. A series of communication nodes are placed along the casing string as part of a downhole wireless telemetry system in the wellbore.

Fig. 2A is a schematic diagram of an exemplary communication node. Fig. 2B is a cross-sectional view of an exemplary communication node taken along a longitudinal axis of the node.

Fig. 3 is a schematic diagram of a layout of a downhole wireless network utilizing multiple topside nodes.

Figures 4A and 4B provide illustrations of monitoring stimulation operations.

FIG. 5 is a flow chart of an illustrative embodiment of a method described herein.

Detailed Description

Various specific embodiments, versions and examples of the invention will now be described, including preferred embodiments and definitions employed herein for purposes of understanding the claimed invention. While the following detailed description gives specific preferred embodiments, those skilled in the art will recognize that these embodiments are merely exemplary, and that the invention may be practiced in other ways. For determining infringement, the scope of the invention will refer to any one or more of the appended claims, including their equivalents and elements or limitations that are equivalent to those that are recited. Any reference to "the invention" may refer to one or more, but not necessarily all, of the inventions defined by the claims.

Term(s) for

Various terms used herein are defined below. To the extent a term used in a claim is not defined below, the broadest possible definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent.

As used herein, the term "communication node" may be used to refer to a topside communication node, an intermediate communication node, and/or a sensor communication node.

As used herein, the term "catheter" refers to a tubular member that forms a physical channel through which something is transported. The conduit may include one or more of a tube, manifold, pipe, etc., or a liquid contained in a tubular member.

As used herein, the term "determining" encompasses a wide variety of actions and can include calculating, evaluating, processing, deriving, investigating, looking up (e.g., looking up in a table, a database or another data structure), ascertaining and the like. Determining may also refer to resolving, selecting, establishing, and the like.

As used herein, the term "fluid" refers to gases, liquids, and combinations of gases and liquids, as well as combinations of gases and solids in which a gas is the major component of a fluid, and combinations of liquids and solids in which a liquid is the major component of a fluid.

As used herein, the term "fluid flow measurement" refers to measuring one or more fluid flow parameters, including but not limited to one or more of velocity, volume, pressure, resistivity, vibration, pressure drop, temperature, impedance, attenuation, density, viscosity, flow type, and the like. Such measurements may be used to determine, for example, fluid viscosity, fluid composition, phase fraction, annular distribution of flow and phase over a cross-section, flow velocity, and the like.

As used herein, the term "flow" refers to a stream (current) or a stream (stream) of fluid. Flow rate may be understood as the amount of fluid passing through a point per unit time. Factors that affect flow may include, but are not limited to, pressure (e.g., flow is directly proportional to the pressure difference across the conduit), length (e.g., flow is inversely proportional to the length of the conduit), viscosity (e.g., flow is inversely proportional to the viscosity of the fluid), temperature of the fluid, density of the fluid, compressibility of the fluid, number of phases (i.e., single or multiple phases) of the fluid, friction, and chemical properties of the fluid.

As used herein, the term "formation" refers to any definable subsurface region. The formation may include one or more hydrocarbon containing layers, one or more non-hydrocarbon containing layers, overburden and/or underburden of any geological formation.

As used herein, the term "hydrocarbon" refers to an organic compound that includes primarily, but not exclusively, hydrogen and carbon elements. Hydrocarbons are generally divided into two categories: aliphatic hydrocarbons, also known as straight chain hydrocarbons, and cyclic hydrocarbons, also known as closed ring hydrocarbons. While hydrocarbons generally contain elemental hydrogen and carbon, in some embodiments, the hydrocarbons may also include minor amounts of other elements or compounds, such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, sulfur. Examples of hydrocarbonaceous materials include any form of natural gas, oil, coal, and bitumen.

As used herein, the term "condensable hydrocarbons" refers to those hydrocarbons that condense at about 15 ℃ and one atmosphere of pressure. Condensable hydrocarbons may include, for example, mixtures of hydrocarbons having carbon numbers greater than 3.

As used herein, the term "hydrocarbon fluid" refers to a hydrocarbon or mixture of hydrocarbons that is a gas or a liquid. For example, the hydrocarbon fluid may include a hydrocarbon or mixture of hydrocarbons that are gaseous or liquid at formation conditions, at treatment conditions, or at ambient conditions (i.e., at about 20 ℃ and 1 atmosphere). Hydrocarbon fluids may include, for example, oil, natural gas, gas condensates, coal bed gas, shale oil, pyrolysis oil, and other hydrocarbons in gaseous or liquid form.

As used herein, "hydrocarbon exploration" refers to any activity associated with determining the location of hydrocarbons in a subsurface region. Hydrocarbon exploration generally refers to any activity performed to obtain measurements by acquiring measurement data related to subsurface formations and associated models of the data to identify potential locations for hydrocarbon accumulations. Thus, hydrocarbon exploration may include acquiring survey data, modeling the survey data to form a subsurface model, and determining possible locations of a subsurface hydrocarbon reservoir. The survey data may include seismic data, gravity data, electromagnetic data, geochemical data, and the like. In some embodiments, hydrocarbon exploration activities may also include drilling exploration wells, obtaining core samples or other fluid samples, and obtaining measurement data from the core or fluid samples.

As used herein, "hydrocarbon development" refers to any activity related to the planning of the production of hydrocarbons and/or the acquisition of hydrocarbons in a subterranean region. Hydrocarbon development generally refers to any activity performed to model the plan for the acquisition and/or production of hydrocarbons from a subsurface formation and associated data to identify preferred development scenarios and methods. For example, hydrocarbon development may include production planning to model and produce cycles for a subsurface formation, determining and planning equipment to use, techniques to use in producing hydrocarbons from a subsurface formation, and so forth.

As used herein, "hydrocarbon production" refers to any activity associated with the extraction of hydrocarbons from a subsurface location, such as a well or other opening. Hydrocarbon production activities may refer to any activity performed to form a wellbore after completion of a well completion and any activity within or on the well. Thus, hydrocarbon production activities include not only primary hydrocarbon recovery, but also secondary or tertiary production techniques such as injecting gas or liquid to increase driving pressure, moving hydrocarbons, or treating hydrocarbons by, for example, chemically, hydraulically fracturing the wellbore to facilitate increased flow rates, well servicing, well logging, and other well and wellbore treatments.

As used herein, "monitored segment" and "plurality of monitored segments" refer to locations along the tubular member that include sensors and/or regions of interest.

As used herein, "unmonitored section" and "a plurality of unmonitored sections" refer to locations along a tubular member that do not include sensors and/or are not areas of interest.

As used herein, the term "multi-zone fluid production well" or "multi-zone production well" refers to a hydrocarbon production well that includes at least two production zones.

As used herein, the terms "near real-time" and "real-time" are used interchangeably and refer to systems and methods that introduce a time delay between the occurrence of an event and the use of processing data, such as by automated data processing or network transmission for display or feedback and control purposes. For example, a near real-time or real-time display depicts an event or situation existing at the current time minus the processing time as an almost live time event. The time delay for "near real time" or "real time" may be on the order of milliseconds to minutes, milliseconds to seconds, or seconds to minutes.

As used herein, the terms "optimal," "optimization," "optimality" (as well as derivatives of those terms and other forms and language-dependent words and phrases) are not meant to be limiting in the sense that the present invention is required to find the best solution or to make the best decision. While a mathematically optimal solution may actually reach the best solution of all mathematically available possibilities, practical embodiments of optimization routines, methods, models and processes may strive towards such goals without actually achieving perfection. Thus, those of ordinary skill in the art having the benefit of this disclosure will appreciate that these terms are more general in the context of the scope of the present invention. These terms may describe one or more of the following: 1) addressing a solution that may be the best available solution, a preferred solution, or a solution that provides specific benefits within a set of constraints; 2) continuously improving; 3) refining; 4) searching for a high point or maximum value of the target; 5) processing to reduce penalty functions; 6) in maximizing, minimizing, or otherwise controlling one or more other factors, etc., one or more factors are sought to be maximized in terms of competing and/or cooperative interests.

As used herein, the term "potting" refers to encapsulating an electrical component with an epoxy, elastomer, silicone or asphalt or similar compound to exclude moisture or vapor. The potting component may or may not be hermetically sealed.

As used herein, the terms "produced fluid" and "production fluid" refer to liquids and/or gases removed from a subterranean formation. The produced fluids may include hydrocarbon fluids and non-hydrocarbon fluids. For example, the produced fluids may include natural gas, pyrolysis shale oil, syngas, coal pyrolysis products, carbon dioxide, hydrogen sulfide, and water (including steam).

As used herein, the term "production casing" includes a liner or any other tubular body secured in a wellbore along an area of interest.

As used herein, the term "production optimization" refers to processes that may be used to increase hydrocarbon fluid production efficiency, hydrocarbon fluid production rate, hydrocarbon fluid recovery, gas/oil ratio, hydrocarbon streamAny method, device, control apparatus, valve, chemical, metrology, data analysis and/or system that utilizes bulk, production plant (plant) to achieve higher production; water cutting, well workover, etc. The production optimization may be real-time production optimization, including partial or full automation, and/or optimization of control settings. Production optimization may be achieved chemically, for example, but not limited to, by preventing or inhibiting scale, paraffin, asphaltene, and/or corrosion through the use of inhibitors of one or more of scale, paraffin, asphaltene, and/or corrosion; extending field life using, for example, defoamers, emulsifiers, foaming agents, flow improvers, tracer dyes and/or water clarifiers, acidification, and the like; using e.g. dissolvers, cleaning agents, scavengers, adsorbents, water flooding, CO₂Chemical methods such as flooding restore or improve flow performance; mechanically, such as, but not limited to, artificial lift, using, for example, a pump (including, but not limited to, electric submersible pumps, gas lift, horizontal surface pumps, subsea lift systems, dewatering pump systems, geothermal pump systems, industrial pump systems, etc.); optimizing gas/water injection; optimizing the size of an oil pipe; optimizing the perforation; nitrogen circulation; and so on. In some cases, production optimization may include sealing the thief zone.

Production optimization may include, but is not limited to, one or more of the following: the method includes the steps of equalizing reservoir inflow along the length of the wellbore, partially blocking flow, delaying water or gas breakthrough by reducing annular velocity across a selected interval (e.g., such as the heel of a horizontal well), adjusting flow from various zones of the production well (including one or more zones of a multizone production well), e.g., overpressured or underpressured, slowing water and/or gas erosion and reducing the amount of by-pass reserve by equalizing pressure drop along the length of the wellbore, e.g., to promote uniform flow of oil and gas through the formation so that arrival of water and gas is delayed and simultaneous. Production optimization may be accomplished using, for example, but not limited to, one or more control devices, including, for example, ICDs, which may be used to manage fluid outflow in an injection well. ICDs may be placed in injection and production wells; or more remotely actuated downhole valves to close or reduce fluid flow from one or more well production zones; effluent control devices, valves and corresponding actuation devices, wellbore isolation devices (including, for example, tool seals, packers, cement plugs, bridge plugs), chemical control devices, and the like.

As used herein, the term "sealing material" refers to any material that can seal the lid of the housing to the body of the housing sufficient to withstand one or more downhole conditions (including, but not limited to, for example, temperature, humidity, soil composition, corrosive elements, pH, and pressure).

As used herein, the term "sensor" includes any sensing device or gauge, such as an electrical device or gauge. The sensors may be capable of monitoring and/or detecting and/or measuring fluid flow parameters including, for example, but not limited to, pressure drop, temperature, fluid flow, fluid type, volume flow, fluid velocity, vibration, resistivity, impedance, attenuation, or other fluid flow data. Alternatively, the sensor may be a position or location sensor.

As used herein, the term "subsurface" refers to an area that occurs below the surface of the earth. For example, the subsurface may be below the top surface of any piece of land at any altitude or range of altitudes, whether above, below, or equal to sea level, and/or below the ground of any piece of water, whether above, below, or equal to sea level.

As used herein, the term "topside communication node" as used herein refers to a communication node that may be located on the topside, near the surface. The topside communication node may be a virtual topside communication node, which may be located underground or downhole, and may serve as a topside node. The virtual topside communication node may be located, for example, at a location including, but not limited to, a bottom of a vertical zone, for example, at a beginning of an offset zone, for example, to communicate with a multi-zone horizontal zone of a multi-zone well. The data may be brought to the surface, e.g., placed into a receiver located at the surface, using, for example, but not limited to, one or more of a wireless connection (e.g., an RF wireless connection), a cable, a fiber optic cable, etc.

As used herein, the term "tubular member" or "tubular body" or "subterranean conduit" refers to any conduit, such as a joint or casing, a portion of a liner, a drill string, a product pipe, an injection pipe, a pipe joint, an underground pipeline, an underwater pipeline, or an above-ground pipeline.

As used herein, the term "wellbore" refers to a subterranean hole made by drilling or inserting a pipe in the subterranean formation. The wellbore may have a substantially circular cross-section or other cross-sectional shape. As used herein, the term "well" may be used interchangeably with the term "wellbore" when referring to an opening in a formation.

As used herein, the term "well data" may include seismic data, electromagnetic data, resistivity data, gravity data, logging data, core sample data, and combinations thereof. The well data may be obtained from memory or from equipment in the wellbore. The well data can also include data associated with equipment installed within the wellbore and a configuration of wellbore equipment. For example, the well data may include a composition of the tubular member, a thickness of the tubular member, a length of the tubular member, a composition of fluids within the wellbore, formation properties, and/or other suitable properties associated with the wellbore.

As used herein, the term "zone" or "zone of interest" refers to a portion of a formation that includes hydrocarbons. The region of interest may also include a formation containing brine or useable water to be isolated.

Description of the invention

The present invention relates to a method of monitoring and optimizing stimulation operations in a reservoir. In particular, the methods and systems utilize downhole telemetry systems, such as a network of sensors and downhole wireless communication nodes, to monitor stimulation operations. For example, the system may employ a series of communication nodes spaced along a tubular member in the wellbore. The communication node wirelessly transmits a signal representing a grouping of information (e.g., information about stimulation operations) in a node-to-node manner and delivers the information from underground to the topside. Thus, information regarding the stimulation operation, such as pressure data, temperature data, flow rate data, density data, vibration data, strain data, and/or acoustic data, may be collected by various downhole sensors before, during, and after the stimulation operation. This information is then transmitted by the wireless communication node to the topside where the well operator can use the information to optimize the stimulation operation.

For example, in one or more embodiments, the method may include obtaining a first data signal from a downhole sensor, wherein the data signal is indicative of at least one subterranean condition (such as temperature, pressure, stress, strain, etc.); transmitting a first data signal from underground to the surface via a downhole wireless network; performing a first stage stimulation operation (e.g., an acidizing and/or hydraulic fracturing operation); obtaining a second data signal from the downhole sensor, wherein the data signal is indicative of at least one subterranean condition (such as temperature, pressure, stress, strain, etc.); transmitting a second data signal from the subsurface to the surface via a downhole wireless network; analyzing the data signal to determine information related to the effectiveness of the stimulation operation (e.g., there has been a pressure change, there has been a temperature change, there has been a stress and/or strain change); modifying, adjusting, and/or optimizing the stimulation plan based on the analyzed data; and producing hydrocarbons.

As another example, in some embodiments, the communication node may be programmed to transmit a signal (e.g., a notification associated with a stimulation operation) to a control unit (e.g., a downhole tool used with the stimulation operation, a topside communication node, and/or other computer system used with the stimulation operation). The notification may include detecting a change in pressure, a change in temperature, a change in flow rate of stimulation fluid, a change in flow rate of hydrocarbon fluid, a change in density, a change in gamma ray emission, a change in vibration, and/or a change in strain. The notification may then be used to adjust the timing or frequency of perforations and/or injection of stimulation fluid, adjust or stop injection of stimulation fluid in one or more wellbore stages, change the type of stimulation fluid used in one or more wellbore stages, and/or adjust the stimulation plan for the next stage.

Thus, the present methods and techniques can be used to monitor and optimize various stimulation operations. For example, the present methods and techniques may be used to monitor acidizing and fracturing operations to minimize and/or optimize the use of raw materials (such as water, acids, proppants, and/or fracturing fluids). For example, the present methods and techniques may be used to improve the reliability of each stage of a stimulation operation by monitoring ball seals and/or fluid flow patterns. For example, the present methods and techniques may be used to monitor pressure, temperature, and/or vibration before and after fracturing, to eliminate one or more fracturing stages, and/or to increase fracture strength in one or more stages. For example, the present methods and techniques may be used to create or modify a hydrocarbon production plan for a formation by utilizing information from one or more wellbores in the formation to create, modify, or optimize a plan for drilling additional wells, well spacing, and/or drilling depths in the formation.

The methods and techniques of the present invention may be further understood with reference to the following drawings, which are described further below. In some figures (such as fig. 1), the top of the page should be towards the earth's surface and the bottom of the page should be towards the bottom of the well. Although the well is typically completed in a substantially vertical orientation, it should be understood that the well may also be completed at an incline and/or horizontally (as shown in FIG. 1). Thus, when the descriptive terms "upper" and "lower" or similar terms are used with reference to the drawings or claims, they are intended to indicate relative positions described on the page of the drawings or with respect to the well, and not necessarily absolute orientations at the surface, as at least some embodiments of the invention have utility regardless of the orientation of the wellbore. Thus, the present invention may have equal utility in vertically completed wells, horizontally completed wells, or multilateral deviated wells, as further described herein.

The present methods and techniques described herein may also be better understood with reference to flow diagrams (such as the flow diagram in fig. 5). While, for purposes of simplicity of explanation, the illustrated methodologies are shown and described as a series of blocks in fig. 5, it is to be understood and appreciated that the methodologies are not limited by the order of the blocks, as some blocks may occur in different orders and/or concurrently with other blocks from that shown and described. Moreover, less than all of the illustrated blocks may be required to implement various embodiments of the exemplary methods. Blocks may be combined or separated into multiple components. Moreover, additional and/or alternative methods may employ additional blocks not shown herein. While the figures illustrate various actions occurring in series, it should be appreciated that various actions may occur in series, substantially in parallel, and/or at substantially different points in time.

FIG. 1 is a side cross-sectional view of an illustrative wellsite 100. The wellsite 100 includes a wellbore 150 penetrated into a subterranean formation 155. Wellbore 150 has been completed as a cased-hole completion for the production of hydrocarbon fluids. Wellsite 100 also includes a wellhead 160. A wellhead 160 is located at the surface 101 to control and direct the flow of formation fluids from the subterranean formation 155 to the surface 101.

The wellhead 160 may be any tubing or valve arrangement that receives reservoir fluids at the top of the well. In the arrangement of fig. 1, the wellhead 160 is of the so-called christmas tree type. A christmas tree type is typically used when the subterranean formation 155 has sufficient in situ pressure to drive production fluids (production fluids) from the formation 155, up the wellbore 150 and to the surface 101. The illustrative wellhead 160 includes a top valve 162 and a bottom valve 164. In some cases, these valves are referred to as "main valves". Other valves may also be used. In a subsea environment, the wellhead may also include a subsea riser assembly (not shown).

It should be understood that instead of using a christmas tree, the wellhead 160 may alternatively include a motor (or prime mover) at the surface 101 that drives the pump. The pump, in turn, reciprocates a sucker rod assembly and an attached positive displacement pump (not shown) downhole. The pump may be, for example, a rocker beam unit or a hydraulic piston pump unit. Still alternatively, the wellhead 160 may be configured to support a string of production tubing with downhole electric submersible pumps, gas lift valves, or other manual lifting means (not shown). The invention is not limited by the construction of the production equipment at the surface unless explicitly stated in the claims.

The wellbore 150 in fig. 1 has been completed with a series of tubular strings, referred to as casing. First, a surface casing 110 string is cemented into the formation. Cement is shown in the annular bore 115 of the wellbore 150 surrounding the surface casing 110. The cement is in the form of an annular sheath 112. The face sleeve 110 has an upper end sealingly connected to the lower valve 164.

Next, at least one intermediate string of casing 120 is cemented into the wellbore 150. The middle string of casing 120 is in sealed fluid communication with upper main valve 162. Again, a cement sheath 112 is shown in the bore 115 of the wellbore 150. The combination of the casing 110/120 and cement sheath 112 in the hole 115 strengthens the wellbore 150 and helps isolate the formation behind the casing 110/120.

It should be understood that the wellbore 150 may, and typically will, include more than one intermediate casing 120 string. In some cases, the intermediate casing string may be a liner. Some of the intermediate casing strings may only be partially cemented in place, depending on regulatory requirements and the presence of migrating fluids in any adjacent formations.

Finally, a production tubing string 130 is provided. The production string 130 is suspended from the intermediate casing string 120 using a liner hanger 131. The production string 130 is a liner that is not tied back to the surface 101. Preferably, all production liners 130 are cemented into place. In the arrangement of fig. 1, a cement sheath 132 is provided around the liner 130 along the entire length of the liner 130.

The production liner 130 has a lower end 134 that extends to an end 154 of the wellbore 150. Thus, the wellbore 150 is said to be completed as a cased-hole well. In fig. 1, the production liner 130 extends through a horizontal portion 190 of the formation 155. The horizontal portion 190 of the wellbore 150 typically extends hundreds of feet. For example, the horizontal portion 190 may extend over 250 feet, or over 1000 feet, or even over 5000 feet. Extending horizontal portion 190 of wellbore 150 such a large distance significantly increases exposure of wellbore 150 to formation 155.

Formation 155 may be any hydrocarbon containing formation. However, in some embodiments, the formation may be a carbonate or sandstone formation with good consolidation but poor permeability, or may be a shale formation with low permeability. For example, in some embodiments, the permeability of the formation may be less than 100 millidarcies ("mD"), or less than 50mD, or less than 10mD, or less than 1 mD. As shown in fig. 1, wells completed in so-called "tight" or "unconventional" formations are typically completed horizontally. Horizontal completions not only significantly increase the exposure of the wellbore to the producing face, but also enable the operator to create fractures that are substantially transverse to the direction of the wellbore. It will be appreciated by those of ordinary skill in the art that the rock matrix will generally "split" in a direction perpendicular to the direction of least principal stress. For deeper wells, this direction is typically substantially vertical. Although fig. 1 illustrates a horizontally completed well, those skilled in the art will appreciate that the present methods and techniques will have equal utility in optimizing stimulation operations in other well arrangements (e.g., vertically completed wells or multilateral deviated wells).

Wellbore 150 is shown in fig. 1 perforated 159 for a fracturing operation. That is, as part of the completion process, the casing is perforated so that lateral holes are shot through the casing and the cement sheath surrounding the casing to allow hydrocarbon fluid to flow into the wellbore. Various techniques may be used to create the perforations. A common technique uses a wellbore tool that includes a perforating gun and an optional frac plug. The wellbore tool may be a wireline tool, or may be an autonomous tool (i.e., a tool that does not require wireline and is not mechanically tethered to equipment outside the wellbore).

For example, a bottom hole assembly ("BHA") including various perforating guns and associated charges may be inserted into the wellbore. The operator may control the BHA to detonate the charges to perform the perforation. Thus, in some embodiments, the BHA may be deployed into the wellbore, moved up and down in the wellbore, allowing an operator to perforate the casing along each zone of interest, and then sequentially isolate the respective zones of interest so that fracturing fluid may be injected into the zones of interest.

As another example, in some embodiments, a process known as just-in-time perforating ("JITP") may be used, whereby an operator can perforate and stimulate a subterranean formation in sequential intervals. The JITP process is further described in U.S. patent No.6,543,538, the disclosure of which is incorporated herein by reference. The JITP procedure may include: perforating at least one interval of one or more subterranean formations traversed by the wellbore using a perforating apparatus; pumping a treatment fluid into the selected interval through the perforations without removing the perforating apparatus from the wellbore; deploying or activating an object or substance in the wellbore to removably inhibit further fluid flow into the treated perforation; and repeating the above process in at least one more interval of the subterranean formation.

An additional process known as "annular coiled tubing fracturing" or ACT-Frac process may be used in conjunction with the JITP process. In the ACT-Frac process, resettable packers are used to provide isolation between zones. Thus, the JITP and ACT-Frac procedures may be used in combination to provide the following techniques: (1) stimulation of multiple target zones or via a single deployment of downhole equipment; (2) enabling selective placement of each stimulation treatment for each individual zone to enhance the productivity of the well; (3) providing transitions between zones to ensure that each zone is treated as designed and that previously treated zones are not inadvertently damaged; and (4) allow for pumping stimulation treatments at high flow rates to promote efficient and effective stimulation. Thus, these multi-zone stimulation techniques enhance hydrocarbon recovery from a subterranean formation comprising multiple stacked subterranean intervals.

Returning to fig. 1, perforations 159 are provided in three separate zones 102, 104 and 106. Each zone may have any length, but generally each zone may represent a length of, for example, up to about 200 feet, or up to 100 feet, or up to 50 feet. In general, the length of each zone may depend on a number of factors, such as the type of rock material in the zone, the permeability of the zone, the porosity of the zone, and/or the hydrocarbon fluid composition in the zone. As described further below, the methods and techniques described herein may be used to determine the optimal length and spacing of desired fracture zones. Although only three sets of perforations 159 are shown, it should be understood that the horizontal portion 190 may have more sets of perforations 159 in additional zones.

The wellbore 150 of fig. 1 also has a string of injection tubing 140. The injection pipe 140 extends from the wellhead 160 down to the subterranean formation 155. In the arrangement of fig. 1, the injection tube 140 terminates near an upper end of the subterranean formation 155. In operation, an operator may stimulate and treat each zone 102, 104, and 106 separately and sequentially. Thus, it should be understood that the injection tube 140 may be pulled through a horizontal portion of the wellbore 150 so that injection fluids may be injected through the perforations 159 in the zones 102, 104, and 106, respectively and sequentially, as desired.

A packer 141 is provided at the lower end of the injection pipe 140. The packer 141 is set when an injection fluid, such as an acid and/or a fracturing fluid, is injected through the set of perforations 159. When it is time to move the injection tube 140 to a different zone or remove it completely from the wellbore 150, the packer 141 will be released.

In preparation for the production of hydrocarbons, the operator may wish to stimulate the formation 155 by performing an acidizing operation. This serves to clean residual drilling mud both along the wall of the wellbore 115 and into the near-wellbore region (the region within the formation 155 near the production casing 130). The acidizing operation may be accomplished by injecting an acidic solution into the wellbore and through the perforations. The use of acidizing solutions is particularly advantageous when the formation contains carbonate rock. Thus, in some embodiments, an operator may inject concentrated formic acid or other acidic composition into the wellbore and direct the fluid into a selected area of interest. The acid helps to dissolve the carbonate material, thereby opening up porous channels through which hydrocarbon fluid can flow into the wellbore. In addition, the acid also helps to dissolve drilling mud that may invade the formation. The acidizing may be performed alone, or in addition to the fracturing operation, such as before or after the fracturing operation.

In a preferred embodiment, the operator may wish to fracture the formation 155. This is accomplished by injecting a fracturing fluid into the formation 155 through perforations 159 at high pressure. The fracturing process creates fractures 108 along the formation 155 to enhance fluid flow into the production casing 130. In the case where the natural or hydraulically induced fracture planes of the formation are vertical, the horizontally completed wellbore (section 190) allows the production casing 130 to intersect multiple fracture planes. Hydraulic fracturing operations typically involve the injection of a viscous fluid (typically a shear-thinning non-newtonian gel or emulsion) into a subterranean formation at high pressures and rates such that the reservoir rock fractures and a network of fractures forms. The fracturing fluid is typically mixed with a granular proppant material (e.g., sand, ceramic beads, or other granular material). After the hydraulic pressure is released, the proppant serves to hold the fracture open. The combination of the fracture and injected proppant helps to increase the flow rate of the treated reservoir.

It is desirable for the well operator to know the effectiveness of any stimulation operations performed within the wellbore. To this end, a downhole telemetry system is provided at the wellsite 100 of FIG. 1. The telemetry system uses a series of communication nodes 180 disposed along the length of the conduit and/or pipe in the wellbore. In some embodiments, the communication nodes may be placed or positioned along the outer diameter of the casing strings 110, 120, and/or 130. In some embodiments, the communication node may be recessed within the pipe body, internal within the pipe body, at a cross-sectional end of the pipe joint, and/or positioned within the through-pipe bore, and combinations thereof. For example, the communication node may be placed on each pipe or casing joint, or may be placed at a selected location along each second or each third pipe joint. In some embodiments, some pipe joints receive two or more communication nodes.

Preferably, the communication node 180 is a stand-alone wireless communication device designed to be attached to the outer surface of a catheter or tubular member, but may also be attached to an inner surface, an end surface (e.g., at the cross-sectional end surface of a connector), embedded within the wall of a catheter or tubular member, or a combination thereof. There are many benefits to using externally placed communication nodes that use acoustic waves. For example, such nodes will not reduce the effective inner diameter of the catheter or tubular member, which would interfere with subsequent assembly or passage of the tube through the inner bore of the catheter or tubular member. In addition, the mounting and mechanical attachment of the communication node to the outer surface can be easily evaluated and adjusted.

The communication node is designed to be attached to the wall of a conduit or tubular member, such as a casing or a pipe. For example, the communication node may be pre-welded to the wall of the conduit or tubular member. Alternatively, the communication nodes may be glued using an adhesive such as epoxy. In some embodiments, it may be preferred to configure the communication node to be selectively attached to and/or detachable from the conduit or tubular member by mechanical means at the wellsite. This can be done, for example, by using a jig. For example, a clamping system may be used that will allow a drilling or service company to mechanically connect/disconnect the communication nodes along the tubular body as it enters the wellbore.

In the arrangement of fig. 1, the communication node 180 may represent a plurality of underground communication nodes 180. Each subsurface communication node 180 is configured to receive and then relay acoustic signals along the length of the wellbore 150, such as from the subsurface formation 155 up to the surface 101. The communication node 180 transmits a sound signal. Preferably, the underground communication node 180 utilizes a two-way transceiver to receive and transmit signals as acoustic waves. The sound waves are preferably at a frequency between about 50kHz and 500kHz or between about 100kHz and about 125 kHz.

The communication nodes also include one or more topside communication nodes 182. In fig. 1, only one topside communication node is shown; however, in some embodiments, two or more topside communication nodes may be used (such as in the embodiment shown in fig. 3). The topside communication node 182 is placed closest to the ground 101. The top-side node 182 is configured to receive acoustic signals from the uppermost underground communication node 180. Thus, signals are passed from underground to topside communication nodes 182 in a node-to-node arrangement through the plurality of communication nodes 180. The topside communication node 182 is generally configured to receive acoustic signals from the plurality of communication nodes 180 and convert the acoustic signals into electrical and/or optical signals, which are then relayed to the receiver 170 at the surface 101. The topside communication node 182 may be above the level (i.e., above the ground) or below the level (i.e., below the ground). In the preferred embodiment, topside communication node 182 is actually connected to wellhead 160.

Fig. 3 provides a simplified illustration of a downhole wireless network utilizing two topside communication nodes. In fig. 3, a wellsite 300 is provided in which a well 310 extends from the surface to the subsurface 301. The wellhead 320 of the well 310 is in a basement 330 directly below ground level. In addition to the wellhead 320, there are two topside communication nodes 370 and 380 within the basement 330. The well 310 extends further into the subsurface from the basement, and may include various casings and production strings, as further described with reference to fig. 1. In fig. 3, there is a surface conductor 350 and a surface housing 340. Within the surface sleeve is a communication node 360. The communication node may be as described with reference to fig. 1, 2A and 2B. In fig. 3, the two top-side communication nodes are shown in separate housings 370 and 380. However, in some embodiments, two or more top-side communication nodes may be combined into a single housing that combines the combined functionality of multiple top-side communication nodes.

The topside communication node(s) serve as a bridge between the downhole communication node and the surface and thus act as a gateway to the downhole wireless network. Thus, in some embodiments, as shown in fig. 3, having two or more topside communication nodes or topside communication node equivalents (i.e., multiple nodes within a single housing) in acoustic contact with the casing, conductor, wellhead, or other topside equipment may provide significant benefits. For example, the use of multiple topside communication nodes may provide improved operational risk, such as by improving the robustness of the communication despite changes in acoustic conditions in the wellbore over time; they may also provide improved network availability, such as by allowing continuous network operation during maintenance (e.g., replacing batteries in the topside node); they may also provide improved energy consumption (e.g., the more topside nodes, the less likely an unsuccessful attempt by the downhole network to reach the topside node); and they may provide increased productivity, such as by allowing the ability to monitor network activity, preview alternate communication settings, identify new issues, and/or facilitate autonomous operation.

For example, the use of multiple topside communication nodes may maximize the likelihood of reliable topside communication with the downhole network. That is, during well operations, the following may occur: one topside communication node may have problems communicating with one or more downhole communication nodes while another topside communication node is able to achieve successful communication. This may often be due to different placements of topside communication nodes relative to downhole communication nodes (and thus different acoustic connections), or may be due to other time-varying adverse acoustic phenomena, such as temperature variations and/or production flow variations.

As another example, another benefit of using multiple topside communication nodes is the ability to have one node engage in telemetry communication while another node is able to monitor, record and/or report the signal being transmitted. In this manner, the non-participating nodes may be used to test and optimize the downhole communication nodes and/or previous alternate communication settings before they are transmitted through the telemetry system.

As yet another example, another benefit of using multiple topside nodes is their ability to provide channel capacity close to that of the network. That is, multiple topside communication nodes may communicate with different downhole communication nodes simultaneously, thus increasing the communication capacity of the network and closer to the theoretical channel capacity of the network.

Returning to FIG. 1, the wellsite 100 illustrates a receiver 170. Receiver 170 includes a processor 172, processor 172 receiving signals transmitted from one or more topside communication nodes 182. Processor 172 may comprise discrete logic, any of a variety of integrated circuit logic types, or a microprocessor. The receiver 170 may also include a screen and keyboard 174 (either as a keypad or as part of a touch screen). The receiver 170 may also be an embedded controller with neither a screen nor a keyboard, which communicates with a remote computer via a cellular modem, satellite, Wi-Fi, or telephone line. In one aspect, the processor 172 is part of a multi-function "smart phone" with a specific "application" and wireless connectivity.

The signal may be received by the receiver 170 via a wire (not shown), such as a coaxial cable, a fiber optic cable, a USB cable, or other electrical or optical communication line. Alternatively, the receiver 170 may receive the resulting signal wirelessly from the topside node 182 via a modem or transceiver or other wireless communication link. In some embodiments, the receiver 170 may receive electrical signals via a so-called class 1, zone 1 conduit, i.e., a housing for electrical wires as defined by NFPA 497 and API 500, to operate in an electrical classification region. Alternatively, data may be transmitted from the topside node to the receiver via an electromagnetic (RF) wireless connection. In some embodiments, infrared or microwave signals may also or alternatively be used.

The signals and data obtained from the various communication nodes may then be used by wellbore operators to monitor and/or optimize hydrocarbon development or hydrocarbon production operations of the wellbore. For example, the received signals and data may be beneficial for enhancing hydrocarbon operations, such as optimizing stimulation operations, as described further below.

The communication node 180 in fig. 1 and 360 in fig. 3 may have various configurations, such as the communication node 255 shown in fig. 2A or the communication node 200 shown in fig. 2B. In general, a communication node includes an elongated body supporting one or more power sources and an electroacoustic transducer. The electroacoustic transducer is associated with a transceiver that receives acoustic signals at a first frequency, converts the received signals to digital signals, and transmits acoustic signals at a second frequency to a next communication node. Thus, the electro-acoustic transducers in each node allow signals to be transmitted as acoustic waves from node to node up the wellbore. Advantageously, the underground communication nodes do not require wires or cables to transmit data to the surface.

Fig. 2A is a diagram of an exemplary communication node 255. The communication node 255 may include a housing 260 and a central processing unit ("CPU") 270; memory 275, which may include instructions or software to be executed by CPU 270; one or more encoding components 285; one or more decoding components 290; a power component 295; and/or one or more sensing components 280; all communicating via bus 216.

Power component 295 is generally configured to provide power to components within communication node 255. The power components may include one or more batteries, capacitors, supercapacitors, fuel cells or other energy storage components. The battery and/or fuel cell may or may not be rechargeable.

CPU270 may be any general purpose CPU, but other types of CPU architectures may be used as long as CPU270 supports the operation of the communication nodes described herein. In one or more embodiments, CPU270 may contain one or more microprocessors and may be a system on a chip ("SOC"), a digital signal processor ("DSP"), an application specific integrated circuit ("ASIC"), and/or a field programmable gate array ("FPGA"). CPU270 may execute various logic instructions to operate communication node 255. For example, the CPU may execute machine-level instructions to perform processing of data and/or signals, as described herein.

The memory 275 may include random access memory ("RAM"), such as static RAM ("SRAM"), dynamic RAM ("DRAM"), synchronous DRAM ("SDRAM"), and the like, read only memory ("ROM"), such as programmable ROM ("PROM"), erasable PROM ("EPROM"), electronically erasable PROM ("EEPROM"). Further, the memory 275 may include NAND flash memory and/or NOR flash memory.

To manage communications, the communication node 255 uses one or more encoding components 285 and one or more decoding components 290 within the housing 260. An encoding component 285, which may include one or more transducers, may be disposed within the enclosure 260 and may be configured to generate acoustic tones and/or induce acoustic tones on a tone transmission medium. One or more decoding components 290, which may include one or more transducers, may be disposed within the housing 260 and may be configured to receive acoustic tones from a tone transmission medium. The encoding component 285 and the decoding component 290 may include instructions stored in memory and used to perform the generation of acoustic tones or decoding of acoustic tones and compression or decompression of data packets into acoustic tones. In one or more embodiments, the encoding component 285 and the decoding component 290 may use the same transducer.

The one or more sensing components 280 may be configured to obtain sensing data (such as measurement data) and transmit the data to a transducer for transmission to other communication nodes. For example, the sensing component 280 may be configured to obtain pressure measurements, temperature measurements, fluid flow measurements, vibration measurements, resistivity measurements, capacitance measurements, strain measurements, acoustic measurements, stimulation and/or hydraulic fracture characteristic measurements, chemical measurements, location measurements, and/or other suitable measurements. Additional examples of suitable sensing components are described with reference to fig. 2B.

Fig. 2B provides another exemplary configuration of the communication node 200 and illustrates a cross-sectional view of the communication node 200 along its longitudinal axis. The communication node 200 includes a housing 210, such as a fluid-tight housing. As described above, the housing 210 is designed to be attached to the outer wall of a joint of a wellbore conduit or tubular member. The communication node may be specifically designed to withstand the corrosive and environmental conditions (e.g., high temperature, high pressure) of the wellbore. For example, the communication node may comprise a steel, fluid-tight housing for holding electronics (e.g., a battery and/or an electroacoustic transducer). In some embodiments, the steel is a corrosion resistant alloy. In some embodiments, it may be desirable to metallurgically match the housing of the communication node with the housing of the conduit or tubular member to help avoid galvanic corrosion at the coupling. In some embodiments, it may be desirable to manufacture the walls of the communication node from a material having a resonant frequency compatible with the resonant frequency of the tubular body. For example, the mechanical resonance of the wall 212 may be at a frequency contained within a frequency band used by the telemetry system.

The housing 210 includes an outer wall 212. The walls 212 are dimensioned to protect the internal electronics for the communication node 200 from wellbore fluids and pressures. In some embodiments, the wall 212 may have a thickness of less than 0.5 inches, such as from 0.01 to 0.5 inches, or from about 0.01 to about 0.4 inches, or from 0.1 to about 0.3 inches, or about 0.2 inches (0.51 cm). The housing 210 optionally also has a protective outer layer 225. The protective outer layer 225 is located on the outside of the wall 212 and provides an additional thin protective layer for the electronic device.

The communication node 200 may have any size suitable for use in a downhole environment. For example, when a communication node resides along a tubular body, its length may be about 12 to 16 inches. The length of the housing 210 of the communication node may be 8 to 10 inches and the length of each opposing shoe 250 may be 2 to 5 inches. Additionally, the communication node may be about 1 inch wide and about 1 inch high. The bottom of the communication node may have a concave profile that substantially matches the radius of the tubular body.

An aperture 205 is formed in the wall 212. The aperture 205 accommodates electronics such as a battery 230, a power cord 235, a transceiver 240, and a circuit board 245. The circuit board 245 will preferably include a microprocessor or electronic module that processes the acoustic signals. An electro-acoustic transducer 242 is provided to convert acoustic energy into electrical energy (or vice versa) and is coupled with the outer wall 212 on the side attached to the tubular body. The transducer 242 may be in electrical communication with one or more sensors 232 and/or 234.

The sensor may be, for example, a pressure sensor, a temperature sensor, or a microphone, or any other sensor as described herein or with reference to fig. 2A. The sensors 232 and/or 234 send signals to the transceiver 240 via short wires or via the printed circuit board 245. The signal from the sensor 232 is converted to an acoustic signal using an electro-acoustic transducer 242 and then transmitted by the transceiver 240 as part of a packet of information. For example, the sensor will measure a piece of data, such as temperature measurements, strain measurements, acoustic noise data, geophone data, etc., and the transducer will then convert this piece of data (e.g., temperature) into an acoustic waveform indicative of the data, which is then transmitted by the transceiver to the next communication node.

In fig. 2B, the sensor 232 resides within the housing 210 of the communication node 200. However, in some embodiments, there may be no sensor 232, but rather the sensor 234 may reside external to the communication node 200. External sensors may be above or below the communication node 200 along the wellbore. In fig. 2B, dashed lines are provided showing the extended connection between the sensor 234 and the electroacoustic transducer 242.

Although fig. 2B illustrates sensors associated with the communication node 200, in the network illustrated in fig. 1, it is not required that all of the communication nodes 180 own or be associated with sensors. That is, some communication nodes 180 may have sensors, while other communication nodes may not and may simply be used to transmit information up and down the wellbore.

Returning to fig. 2B, the communication node 200 may also optionally include a shoe 250. For example, the node 200 may include a pair of shoes 250 disposed at opposite ends of the wall 212. Each shoe 250 provides a chamfer that helps prevent the node 200 from hanging up on the outer tubular body or surrounding formation as the case may be during break-in or pull-out. The shoe may have a protective outer layer 222 and an optional cushioning material beneath the outer layer 222.

As seen in fig. 2B, the communication node has an independent power supply 230. The independent power source 230 may be, for example, a battery or a fuel cell. Having a power supply residing within the housing of the communication node avoids the need to pass electrical connections through the housing, which can compromise fluid isolation.

As described above with reference to fig. 1, 2A, and 2B, each communication node may have the capability to send and receive signals, enabling a downhole wireless network to transmit data from the subsurface to the surface in a node-to-node arrangement. In a preferred embodiment, the data transmitted between the nodes is represented by sound waves. In some embodiments, acoustic telemetry data transmission is accomplished using a multiple frequency shift keying ("MFSK") modulation method. While MFSK is well suited for use in the downhole wireless networks described herein, its use is by way of example only and not intended to be limiting. That is, various alternatives to known digital data modulation are available, such as frequency shift keying ("FSK"), multi-frequency signaling, phase shift keying, pulse position modulation, and on/off keying.

Thus, signals generated by the electrical transducer within the communication node pass through the housing of the communication node to the tubular body (such as a production or casing string) and propagate along the tubular body to other communication nodes. The data is then retransmitted up the wellbore in a node-to-node arrangement until the top communication node and well operators are reached. The retransmitted signal represents the same sensor data originally transmitted by the first sensing communication node.

In some embodiments, acoustic signals may be generated and received by magnetostrictive transducer(s) that include a coil wound on a core as a transceiver. In some embodiments, the acoustic signal is generated and received by a piezoceramic transducer. In either case, the electronically encoded data is converted into acoustic waves that will be carried through the wall of the tubular body in the wellbore.

Acoustic telemetry along tubular members is characterized by multipath or reverberation lasting for millisecond periods. Thus, the transmitted tones of a few milliseconds duration determine the primary receive frequency within the additional millisecond period. Preferably, the communication node determines the frequency of transmission by receiving or "listening" to sound waves over a time period corresponding to the reverberation time, which is typically much longer than the transmission time. The tone duration should be long enough so that the spectrum of the tone burst has negligible energy at the frequencies of the adjacent tones, and the listening time must be long enough so that the amplitude of the multipath is significantly reduced. For example, the tone duration may be 2 milliseconds (ms), and then the transmitter may remain silent for 48ms before transmitting the next tone. However, the receiver will listen for 50ms (2+48) to determine the frequency of each transmission and make the frequency determination more deterministic with a long reverberation time. Advantageously, the energy required to transmit data is reduced by transmitting for short periods of time and exploiting multipath to extend the listening time during which frequencies of transmission can be detected.

For example, as described above, MFSK modulation may be employed, in which each tone is selected from a 16 tone alphabet so as to represent 4-bit information. For example, at a 50ms listening time, the data rate is 80 bits per second.

The tones are selected such that the signal is at least two nodes away from the transmitter node in a frequency band above which ambient and electronic noise is detected, so that if one node fails, it can be bypassed by transmitting data directly between its nearest neighbors above and below it. For example, the tones may be evenly spaced in periods within a frequency band of about 100kHz to about 125 kHz. As another example, the tones may be evenly spaced in frequency within a frequency band of about 100kHz to about 125 kHz.

Preferably, the node employs a "frequency hopping" method, wherein the last transmitted tone is not immediately reused. This prevents the expanded reverberation from being mistaken for a second transmitted tone at the same frequency. For example, in the MFSK modulation scheme, 17 tones are used to represent data; however, the last used tone is excluded, so that only 16 tones are actually available for the segment at any one time.

Any extraneous noise in the signal can be mitigated by using well-known conventional analog and/or digital signal processing methods. Noise removal and signal enhancement may involve conveying the acoustic signal through a signal conditioning circuit using, for example, a band pass filter.

Returning to fig. 1, each communication node is associated with a particular conduit or tubular member, and may be associated with a particular pipe joint. The joints of tubing in turn have a known location or depth along the wellbore. Each acoustic wave initially transmitted from a communication node will represent a packet of information. The packet will include an identification code that tells a receiver (such as receiver 170 in fig. 1) the origin of the signal, i.e., from which communication node 180 the signal came. For example, the packet may include amplitude values originally recorded by the communication node 180 for its associated pipe joint. Packets of information are then relayed from communication node 180 node-to-node below ground to one or more topside nodes 182a on receiver 170.

As such, each signal defines a packet of information having at least an identifier (such as an acoustic amplitude value) of the underground communication node that originally transmitted the signal. When the signal reaches a receiver at the surface, the signal is processed. This involves identifying which communication node the signal originated from and then determining the location of that communication node along the wellbore.

The data packet may also include data obtained from one or more sensors associated with the communication node. As described above, a communication node may contain or be associated with one or more sensors. The sensors may be, for example, fluid velocity measurement devices, temperature sensors, pressure sensors, fluid density sensors, microphones, ultrasonic sensors, doppler shift sensors, chemical sensors, imaging sensors, impedance sensors, attenuation sensors, fluid resistivity sensors, and/or other useful types of sensors. Generally, a sensor sends a signal to a transceiver, which then converts it into an acoustic signal using an electroacoustic transducer, which is then sent by the transceiver as part of a packet of information. Thus, the communication node may be configured to receive signals from associated sensors and to transmit signals indicative of readings taken by the sensors.

As described above, the present methods and techniques may be useful for monitoring and optimizing stimulation operations (such as fracturing and/or acidizing operations) in a reservoir. For example, fig. 5 is an exemplary flow diagram 500 in accordance with embodiments of the present technique. The flow diagram 500 is a method for performing a stimulation operation, such as an acidizing or hydraulic fracturing operation. In general, the method may comprise: the method includes obtaining data signals before and after the stimulation operation, evaluating and analyzing the data signals to determine information about the stimulation operation, and using the analyzed data to modify, adjust, and/or optimize the stimulation operation.

Although not shown in fig. 5, the method may first include providing a downhole wireless network as described herein. The network may include a series of communication nodes attached to a pipe in the wellbore, wherein adjacent communication nodes are configured to communicate by acoustic signals transmitted through the pipe. The network further comprises at least one sensor associated with at least one communication node.

Once the downhole wireless network is installed, the method at block 502 may include obtaining a first data signal from a downhole sensor. Typically, the downhole sensor is associated with at least one communication node in a downhole wireless network. The data signal may include measurements from the sensors and is generally indicative of at least one subsurface condition. For example, the data signals may include temperature measurements, pressure measurements, stress measurements, strain measurements, and the like. The data signals are then transmitted from the subsurface to the surface via a series of communication nodes in a downhole wireless network at block 508.

At block 504, a first stage stimulation operation is performed. For example, stimulation operations may include perforating at least one interval of a subterranean formation traversed by a wellbore; pumping, introducing and/or injecting a treatment fluid (such as an acid solution or a hydraulic fracturing fluid) into at least one interval of the wellbore; and/or deploying or activating an article or substance (such as a ball sealer) in the wellbore to prevent further fluid flow into an interval of the wellbore. Thus, in one or more embodiments, the stimulation operation may be an acidizing treatment, and at block 504, an acid solution may be introduced and/or injected into the subterranean formation. As another example, in one or more embodiments, the stimulation operation may be a hydraulic fracturing operation, and at block 504, one or more perforations may be formed in the subterranean formation using a perforating gun and/or a hydraulic fracturing fluid may be introduced and/or injected into the subterranean formation.

At block 506, a second data signal is obtained from a downhole sensor. The downhole sensor may be the same downhole sensor that obtained the data signal at block 502, or may be a different downhole sensor. The second data signal may include measurements from the sensor and is generally indicative of at least one subsurface condition. For example, the second data signal may include a temperature measurement, a pressure measurement, a stress measurement, a strain measurement, and the like. Then, at block 508, the second data signal is transmitted from the subsurface to the surface via a series of communication nodes in the downhole wireless network.

At block 510, the data signals are analyzed to determine information about the effectiveness of the stimulation operation. For example, analysis may be performed to determine whether there is a change in pressure, temperature, and/or stress and/or strain.

The analyzed data is then used to modify, adjust, and/or optimize the stimulation operation at block 512. For example, at least one condition under which a stimulation operation should be linked may be determined. As an example, a determination may be made that an amount of treatment fluid (e.g., an acid solution and/or a hydraulic fracturing fluid) introduced into the subterranean formation needs to be increased, decreased, or stopped; the type of treatment fluid (e.g., acid solution and/or hydraulic fracturing fluid) needs to be changed; it may be desirable to increase or decrease the pressure at which treatment fluids (e.g., acid solutions and/or hydraulic fracturing fluids) are introduced into the subterranean formation. As another example, it may be determined that the stimulation operation at that interval in the wellbore was successful and the operator may move to perform the stimulation operation in the next interval of the wellbore.

In some embodiments, the downhole sensor(s) may comprise a temperature sensor, and the data signals collected from the sensors and transmitted by the communication node may comprise signals representative of temperature readings taken by the temperature sensor. For example, a communication node may transmit a packet of information that includes (i) an identifier of the subsurface communication node that originally transmitted the data, and (ii) an acoustic waveform indicative of the temperature readings taken by the temperature sensor. Temperature signals from before, during, and after stimulation operations may be analyzed to determine temperature changes indicative of fracture formation activity, increased hydrocarbon fluid flow, or changes in fluid type. In some embodiments, temperature readings from multiple downhole sensors may be transmitted to the surface. The multiple temperature readings may be averaged to determine a moving average temperature of a portion of the wellbore (such as the interval perforated and/or stimulated) and/or a particular section of casing. The average temperature may then be compared to temperature readings for other intervals and/or other portions of the casing that were not perforated and/or not stimulated. In some embodiments, the temperature readings may be integrated into a subsurface map or subsurface model to help analyze fracture formation and/or hydrocarbon flow through the formation over time, such as before, during, and/or after a stimulation operation. Data from temperature sensors may also be integrated with data from other types of sensors.

In some embodiments, the downhole sensor(s) may include strain gauges that may be used to determine changes in stress on the casing during and/or after stimulation operations, and/or to identify changes in volume near the sensors. For example, strain gauge data may be used to detect wellbore pressure increases due to influx of reservoir fluids through the stimulation formation. Thus, data from the strain gauges may be included as part of a packet of information sent to a receiver at the surface for analysis, and the packet of information may include (i) an identifier of the subsurface communication node that originally transmitted the data, and (ii) an acoustic waveform indicative of the stress readings taken by the strain gauges. In some embodiments, stress readings from multiple downhole sensors may be transmitted to the surface. Multiple stress readings may be averaged to determine an average strain for a portion of the wellbore (such as a perforated and/or stimulated interval) and/or a particular section of casing. The average stress may then be compared to stress readings from other intervals and/or other portions of the casing that were not perforated and/or not stimulated. In some embodiments, the stress readings may be integrated into a subsurface map or subsurface model to help analyze fracture formation and/or hydrocarbon flow through the formation over time, such as before, during, and/or after a stimulation operation. The data from the strain gauges may also be integrated with data from other types of sensors.

In some embodiments, a microphone may be placed within or associated with a selected subsurface communication node. Passive acoustic data gathered by the microphone may be used to detect flowing wellbore fluids, particularly gases. When the gas flows through a small gap, it will generate ambient noise over a wide frequency range, which can be detected by passive acoustic sensors in the node. Thus, data from the microphone may be included as part of a packet of information that is transmitted to a receiver at the surface for analysis, and the packet of information may then include (i) an identifier of the underground communication node that originally transmitted the data, and (ii) an acoustic waveform indicative of the acoustic data gathered by the microphone. In some embodiments, readings from multiple downhole microphones may be transmitted to the surface. The intensity and variation of the acoustic frequency measured by the multiple microphone readings may be averaged to determine an average microphone reading for a portion of the wellbore (such as the interval being perforated and/or stimulated) and/or a particular section of casing. The average microphone readings may then be compared to microphone readings for other intervals and/or other portions of the casing that were not perforated and/or not stimulated. In some embodiments, the microphone readings may be integrated into a subsurface map or subsurface model to help analyze fracture formation and/or hydrocarbon flow through the formation over time, such as before, during, and/or after a stimulation operation. Data from the microphone sensor may also be integrated with data from other types of sensors.

In some embodiments, the downhole sensor(s) may comprise geophones. For example, at least three communication nodes may each be associated with a geophone. Geophones "listen" for elastic waves generated during formation stimulation operations (e.g., fracturing operations). These waves are converted into acoustic signals and then transmitted to the surface by a transceiver in the associated communication node. Thus, the transmitted signal may represent a packet of information that includes (i) an identifier of the subsurface communication node that originally transmitted the data, and (ii) an acoustic wave indicative of an elastic wave caused by movement of rock within the subsurface formation during the fracturing operation.

As with any seismic analysis process, this process requires that certain parameters be obtained in advance for the rock matrix within the subterranean formation. This includes knowledge of the rock type and density so that the P-wave (pressure) velocity and/or S-wave (shear) velocity can be determined. The determination is typically based on existing data obtained from the tool, core sample, or previously measured seismic data.

When the associated sensors comprise geophones, the plurality of sensors will detect elastic waves within the subsurface formation. A set of waves will be detected within a very small time frame, such as 250 microseconds. It is then assumed that those waves in the set indicate the same microseismic event. An algorithm is applied that compares the time at which each event is heard with the known velocity v of the elastic wave. Triangulation may then be performed to determine the origin of the analyzed elastic waves.

Triangulation data is accumulated at the surface. In one aspect, a binary code is assigned to the triangulation results, the code indicating azimuth, direction, and depth. The triangulation results are then compiled so that a map of the microseismic event can be created. In the seismic field, this step is called "imaging". The map is viewed at the surface to determine the extent of subsurface fractures across various zones, such as zones 102, 104, and 106 in FIG. 1.

As can be seen, the sensors may gather various data including temperature measurements, strain measurements, acoustic noise data, geophone data, and the like. All of these data can be integrated and considered together when evaluating stimulation operations. In some embodiments, evaluating may include comparing an amplitude value from the second data signal obtained at block 506 to a baseline value (such as the first data signal obtained at block 502). Alternatively, the evaluation may include comparing the amplitude value to a baseline that is an expected value determined from past experience or obtained from a database of stimulation data obtained over time.

In block 510, these comparisons may be used to determine various details regarding stimulation operations. For example, if the data indicates that the hydrocarbon fluid flow rate has not increased after a stimulation operation, it may be determined that further stimulation is needed for that interval of the wellbore. Alternatively, if the data indicates an increase in hydrocarbon fluid flow after a stimulation operation, it may be determined that no further stimulation is needed in that interval. All of this information can then be used to optimize the stimulation strategy of the wellbore at block 512.

At block 514, hydrocarbon fluids may then be produced from the wellbore.

The methods and techniques described herein may be particularly useful in staged stimulation operations. In a staged operation, the wellbore may have multiple individual target zones identified for stimulation operations. Such a target area may represent a total vertical thickness of the subsurface formation of approximately 60 meters (200 feet). When there are multiple or stratified reservoirs to be hydraulically fractured or very thick hydrocarbon containing formations (above about 40 meters) more sophisticated stimulation techniques are often required to treat the entire target formation. In this regard, operators often isolate the various zones to ensure that each individual zone is not only perforated, but also properly fractured and handled. In this manner, the operator ensures that fracturing fluid and/or stimulation agent is injected through each set of perforations and into each zone of interest to effectively increase the flow capacity at each desired depth. The methods and techniques of the present invention may be utilized to efficiently monitor each region of interest and identify when the operator should proceed to the next region of interest.

To isolate selected regions of interest, various diversion techniques may be employed, where "diverting" refers to diverting injected fluid from entering a collection of perforations such that fluid enters primarily only one selected region of interest. Various known transfer techniques include the use of: mechanical devices, such as bridge plugs; a packer; a downhole valve; a sliding sleeve; and a baffle/plug combination; a ball sealer; particles such as sand, ceramic materials, proppants, salts, waxes, resins, or other compounds; chemical systems such as viscosified fluids, gelled fluids, foams, or other chemically formulated fluids; and a restricted entry method. These and other methods for temporarily preventing fluid flow into or out of a given set of perforations are further described in U.S. patent No.6,394,184, the disclosure of which is incorporated herein by reference.

The method herein may include deploying a first perforating gun assembly into a wellbore. The first perforating gun assembly can be configured to detect a first selected zone of interest along the wellbore. Thus, when the first perforating gun assembly is pumped or otherwise dropped down the wellbore, it will monitor its depth or otherwise determine when the first selected zone of interest is reached. In some embodiments, it may detect when the first selected region of interest is reached. For example, the perforating gun assembly can detect the first selected zone of interest by matching acoustic characteristics of a particular communication node within the wellbore.

The method may further include firing along the first region of interest. The shot creates a perforation. The shot penetrates the surrounding production casing string and extends into the subterranean formation.

The method may also include providing a second perforating gun assembly. The second perforating gun assembly can be configured to detect a second selected zone of interest along the wellbore. Thus, when the second perforating gun assembly is pumped or otherwise dropped down the wellbore, it will monitor its depth or otherwise determine when the second selected zone of interest is reached. For example, the second perforating gun assembly can determine when it is in the second selected zone of interest by matching the acoustic characteristics of a particular communication node within the wellbore in the selected zone of interest. A second perforating gun assembly is fired along the second zone of interest to create perforations in the second zone of interest.

The method may further include injecting hydraulic fluid at high pressure to fracture the formation. The formation may be fractured by directing fluid through the perforations along a first selected region of interest, directing fluid through the perforations along a second region of interest, or both.

When multiple regions of interest are perforated and ruptured, it may be desirable to use a diverter as described above. For example, frac plug assemblies and/or ball sealants may be used. Thus, a ball sealant may be pumped downhole to seal the perforations. In some embodiments, the ball sealant may be carried downhole in a container and released via command (from an onboard controller or from a communication node).

It may also be desirable for the operator to circulate the acid solution after perforating and fracturing each zone.

Examples of the use of the present methods and techniques for phased operation may be as further described with reference to fig. 4A and 4B.

Fig. 4A illustrates a single wellbore 400 traversing a subterranean formation. As shown, the wellbore moves from left to right along the horizontal side of the wellbore with increasing distance. Each box in the wellbore depiction illustrates a zone or interval of the wellbore in the stimulation plan. As seen in fig. 4A, perforations have been made along the wellbore in each interval. Sensor data has been collected along the length of the wellbore to provide an indication of fluid flow after stimulation operations. Sensor data from intervals 401 and 402 indicate that these zone flows are moderate, while sensor data from interval 403 indicates that this zone flow is low. Sensor data from other intervals indicate that they have acceptable inflow levels. By viewing the sensor data, the operator may determine that zones 401, 402, and/or 403 may need to be re-fractured to increase flow through the zones, may need to use different types of stimulation fluids to better target the zones, may need more proppant in the zones, and in this manner, the operator may optimize the stimulation operation of the wellbore 400 by optimizing stimulation in each zone of the wellbore.

Fig. 4B illustrates the same wellbore 400 as fig. 4A, and a new wellbore 410 drilled adjacent to the wellbore 400 in the same subterranean formation. As with fig. 4A, in fig. 4B, the wellbore travels from left to right along the horizontal side of the wellbore as the distance increases. Each box in the wellbore depiction illustrates a zone or interval of the wellbore in the stimulation plan. In formulating a stimulation plan for the wellbore 410, the operator uses the data from the wellbore 400 to optimize the stimulation plan. For example, at zones in wellbore 410 that correspond laterally to zones 401 and 402, the operator plans to use different stimulation techniques to increase the flow from these zones. For example, the operator may use a different (e.g., higher) pressure and/or more proppant in order to increase the flow from the wellbore 410. To further optimize the stimulation plan for the wellbore 410, the operator may also choose not to perform any stimulation operations at a section of the wellbore 410 that laterally corresponds to the section 403 of the wellbore 400. Because the flow rates of the section 403 in the wellbore 400 are very low, the operator can determine that the corresponding section in the stimulation wellbore 410 is unlikely to provide any producible flow rates, and as such, the operator can be more time and resource efficient by not stimulating the corresponding section in the wellbore 410.

The methods and systems described herein may be used to provide real-time information based on sensed data collected downhole during a stimulation operation and allow an operator to evaluate the stimulation operation in real-time to adjust and optimize the stimulation operation as needed. For example, the methods and techniques may be used to collect real-time pressure data, temperature data, flow rate data, density data, gamma ray data, vibration data, strain data, and/or acoustic data from sensors associated with one or more downhole communication nodes before, during, and after stimulation operations. The collected data is then wirelessly transmitted to the surface via the communication node for analysis so that the operator can use it to make operational changes to the stimulation operation being performed and/or to modify or optimize the stimulation plan for other wellbores in the same reservoir.

Thus, in preferred embodiments, the methods described herein can be used to monitor a stimulation operation to optimize the use of raw materials in the stimulation operation. For example, data feedback from the stimulation stage (e.g., pressure, temperature, vibration, pH, porosity, permeability, etc.) may be used to guide the type and amount of treatment fluid (e.g., acid solution and/or hydraulic fracturing fluid) introduced into the next stimulation stage. The sensor data may also be used to optimize the pressure and/or volume of treatment fluid introduced into the wellbore to ensure a uniform inflow or injection rate. In addition, the sensor data may be used to monitor fluid flow patterns and proppant flow patterns to provide real-time data regarding the need for additional transfer techniques (such as ball sealants, etc.).

The methods described herein may also be used to modify a stimulation plan by providing real-time data to an operator indicating that no further stimulation operations are needed. For example, where the wellbore includes multiple stages, by monitoring sensor data before and after stimulation operations at each stage, it may be determined that a stage adjacent to or connected to the stage currently being stimulated is also being effectively stimulated. That is, while stage X has been perforated and treatment fluid has been introduced into that stage, stage Y has also experienced an increase in fluid flow after the stimulation treatment of stage X. As such, the operator may determine that stage Y does not require perforation and/or treatment with one or more treatment fluids. As such, the stimulation plan may be optimized by skipping any stimulation operations in stage Y.

The methods described herein may also be used to determine whether a fracturing stage is in a producing zone. For example, after the fracturing stage N, the subterranean formation can be monitored by measuring fluid density, dielectric constant, conductivity, and differential pressure. Using the collected data, it can be determined whether the fracturing stage N is in the producing zone. If determined to be within the production zone, then more stimulation operations may be planned for that stage or adjacent stages to improve production recovery.

The methods described herein may also be used to create an optimized stimulation plan for a grouping of wells in a reservoir region. For example, the methods and techniques may be used to create or modify a hydrocarbon production plan for a formation by utilizing information from one or more wellbores in the formation to create, modify, or optimize a plan for drilling additional wells in the formation, well spacing, and/or drilling depth. For example, the plan may be optimized by reducing the number of wells in the area, or only certain portions of the area may be drilled based on a larger reservoir stratigraphic map generated from the collected data. Thus, using the drilling data and the collected data together, a reservoir stratigraphic map of the reservoir region may be generated in 2D or 3D. This map may be used to determine well spacing and drilling depth within the area, and may be used to guide wells to "optimal locations" within the reservoir area to optimize the productivity of the wells.

Thus, as described herein, the present invention may be used to monitor and optimize stimulation operations in a reservoir. The methods and systems may advantageously provide real-time information of downhole conditions before, during, and after stimulation operations. This information may then be used by well operators to modify, adjust, and/or optimize stimulation operations to improve hydrocarbon production from the subsurface. Further, because the methods and systems described herein utilize a downhole wireless communication node to transmit data to the surface, there is no need to interrupt stimulation operations to lower wireline tools used to collect and/or transmit data.

It should be understood that the preceding is merely a detailed description of specific embodiments of this invention and that numerous changes, modifications, and alternatives to the disclosed embodiments can be made in accordance with the disclosure here without departing from the scope of the invention. Accordingly, the foregoing description is not meant to limit the scope of the invention. Rather, the scope of the invention is to be determined solely by the appended claims and their equivalents. It is also contemplated that structures and features implemented in this example may be altered, rearranged, substituted, deleted, duplicated, combined, or added to each other. As such, it will be apparent to those skilled in the art that many modifications and variations to the embodiments described herein are possible. All such modifications and variations are intended to fall within the scope of the invention, as defined by the appended claims.

Claims (14)

1. A method for monitoring and evaluating a stimulation operation, comprising:

obtaining a first data signal indicative of a subterranean condition from a downhole sensor;

a first stage of performing a stimulation operation;

obtaining a second data signal from a downhole sensor, the second data signal indicative of a subterranean condition after a first phase of a stimulation operation;

transmitting a data signal from the subsurface to the surface over a downhole wireless network, wherein the downhole wireless network comprises a series of communication nodes connected to pipes in the wellbore, and wherein adjacent communication nodes are configured to communicate by acoustic signals transmitted through the pipes;

analyzing the data signal to assess a first stage of the stimulation operation;

modifying, adjusting or optimizing the stimulation operation based on the evaluation results; and

hydrocarbons are produced.

2. The method of claim 1, wherein each communication node comprises

A sealed housing;

an electroacoustic transducer and associated transceiver residing within the housing configured to relay signals, each signal representing a packet of information including (i) an identifier of a subsurface communication node that originally transmitted the signal, and (ii) a signal representative of a reading taken by a downhole sensor; and

an independent power source residing within the housing for providing power to the transceiver.

3. The method of claim 1 or 2, wherein the downhole wireless network comprises at least one topside communication node residing near the surface, and a series of subsurface communication nodes along the wellbore below the topside communication node; and

wherein at least one topside communication node transmits signals from an uppermost underground communication node to a receiver at the surface.

4. The method of any of claims 1-3, wherein the downhole sensor comprises one or more of: fluid velocity measurement devices, temperature sensors, pressure sensors, fluid density sensors, microphones, ultrasonic sensors, doppler shift sensors, chemical sensors, imaging sensors, impedance sensors, attenuation sensors, and fluid resistivity sensors.

5. The method of any one of claims 1-4, wherein the first data signal comprises one or more of: pressure data, temperature data, flow rate data, density data, vibration data, strain data, and acoustic data.

6. The method of any of claims 1-5, wherein the second data signal comprises one or more of: pressure data, temperature data, flow rate data, density data, vibration data, strain data, and acoustic data.

7. The method of any of claims 1-6, wherein the first stage of stimulation operations comprises one or more of: perforating at least one interval of a subterranean formation traversed by a wellbore; pumping, introducing and/or injecting a treatment fluid into at least one interval of the wellbore; and deploying or activating an item or substance in the wellbore to prevent further fluid flow into an interval of the wellbore.

8. The method of claim 7, wherein the treatment fluid comprises an acid solution or a hydraulic fracturing fluid.

9. The method of claim 7, wherein the deployed or activated article or substance is a ball sealant.

10. The method of any one of claims 1 to 9, wherein modifying, adjusting, or optimizing a stimulation operation comprises one or more of: (i) increasing or decreasing the amount of treatment fluid introduced into the subterranean formation; (ii) altering the type of treatment fluid introduced into the subterranean formation; (iii) increasing or decreasing the pressure at which the treatment fluid is introduced into the subterranean formation.

11. The method of any one of claims 1-10, wherein the underground communication nodes are spaced apart such that each joint of the conduit supports at least one underground communication node.

12. The method of any of claims 1-10, wherein the underground communication nodes are spaced apart at intervals of about 20 feet to about 40 feet.

13. The method of any one of claims 1-10, wherein each communication node is configured to receive sound waves of a first frequency and then transmit sound waves of a second frequency up the wellbore to a next communication node.

14. The method of any one of claims 1-13, wherein the downhole sensor resides within a housing of at least one subterranean communication node.

Images